Dominion Energy, Inc. (D) Q2 2011 Earnings Report, Transcript and Summary

Good morning, and welcome to Dominion's Second Quarter Earnings Conference Call. On the call today, we have Tom Farrell, CEO, and other members of Senior Management. [Operator Instructions] I would now like to turn the conference over to Tom Hamlin, Vice President of Investor Relations for Safe Harbor statement.

Good morning, and welcome to Dominion's Second Quarter 2011 Earnings Conference Call. During this call, we will refer to certain schedules included in this morning's earnings release and pages from our earnings release kit. Schedules in the earnings release kit are intended to answer the more detailed questions pertaining to operating statistics and accounting. Investor Relations will be available after the call for any clarification of these schedules. If you've not done so, I encourage you to visit our website, register for email alerts and view our second quarter 2011 earnings documents. Our website address is www.dom.com/investors. In addition to the earnings release kit, we have included a slide presentation on our website that will guide this morning's discussions. And now for the usual cautionary language. The earnings release and other matters that will be discussed on the call today may contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual report on Form 10-K and our quarterly report on Form 10-Q for a discussion of factors that may cause results to differ from management's projections, forecasts, estimates and expectations. Also on this call, we will discuss some measures of our company's performance that differ from those recognized by GAAP. Those measures include our second quarter operating earnings and our operating earnings guidance for the third quarter and full year 2011, as well as operating earnings before interest and tax, commonly referred to as EBIT. Reconciliation of such measures to the most directly comparable GAAP financial measures we are able to calculate and report are contained in our earnings release kit. Joining us on the call this morning are our CEO, Tom Farrell; our CFO, Mark McGettrick, and other members of our management team. Mark will begin with a discussion of the earnings results for the second quarter, as well as our guidance for the third quarter. He will also discuss our financing activities and provide an update on our hedge positions. Tom will discuss our operating and regulatory activities, and we will then take your questions. I will now turn the call over to Mark McGettrick.

Good morning, everyone, and thank you for joining us. Dominion had a very strong second quarter. Operating earnings were $0.59 per share, which were in the top of our earnings guidance range of $0.50 to $0.60 per share. Weather, which boosted earnings for the second quarter of last year by $0.06 per share, added only $0.01 compared to normal. Despite the normal weather, both of our electric business segments delivered earnings at or above the top of the respective guidance ranges. Other factors impacting the results for the quarter relative to guidance were lower interest costs and higher income taxes. GAAP earnings were $0.58 per share for the second quarter. The principal differences between GAAP and operating earnings for the quarter were the benefit of a resolution of a lawsuit with the Department of Energy over spent nuclear fuel, offset by severance charges related to the previously announced closing of the Salem and State Line merchant generation plants. A summary and a reconciliation of GAAP to operating earnings can be found on Schedules 2 and 3 of the earnings release kit. Now moving to results by operating segment. At Dominion Virginia Power, EBIT for the second quarter was $227 million, near the high end of our guidance range. Higher transmission revenues and a higher contribution from Dominion Retail were principal factors in this strong performance. EBIT for Dominion Energy was $184 million, just above the midpoint of our guidance range. A strong contribution from Producer Services offset lower results from our distribution companies. Dominion Generation produced EBIT of $372 million for the second quarter, exceeding the high end of our guidance range. Higher ancillary service revenues and higher-than-expected merchant generation margins were the principal favorable earnings drivers. Overall, we are very pleased with all of our operating segment results. Moving to cash flow and treasury activities. On our last call, we outlined our financing plans for the remainder of the year, including debt issuances of $1.2 billion to $1.5 billion. To take advantage of the current interest rate environment, we have hedged treasury rates for $600 million of the debt need for 2011 and have taken a further step of locking in treasury rates related to over half of our 2012 needs. As a reminder, we do not plan to issue any net common stock in 2011. Also, other than the potential issuance of up to $300 million of stock through our stock purchase and Dividend Reinvestment Plan, we do not plan to issue any net common stock in 2012. Liquidity at the end of the quarter was $1.7 billion. For statements of cash flow and liquidity, please see Pages 14 and 27 of the earnings release kit. To offset the impact of bonus depreciation on our earnings, we announced a plan to repurchase between $600 million and $700 million in common stock during the year. To the end of the second quarter, we had repurchased approximately 13 million shares at a cost of about $600 million. We will make a decision of whether or not to repurchase the additional $100 million later in the year. Now to earnings guidance. Our earnings -- our operating earnings guidance for 2011 is unchanged at $3 to $3.30 per share. We continue to expect annual earnings per share growth of 5% to 6% growth beginning in 2012. For the third quarter of 2011, Dominion expects operating earnings in the range of $0.90 to $1 per share, compared to operating earnings of $1.03 per share in the third quarter of 2010. Last year's above normal temperatures added $0.08 per share to third quarter earnings. Other factors leading to lower third quarter earnings compared to last year include lower expected margins from our merchant generation business and a higher effective income tax rate. Offsetting these factors are higher expected base and rider-related revenues and a lower share count. GAAP earnings for the third quarter of 2010 can be found on Page 40 of the earnings release kit. As to hedging, you can find the update of our hedge positions on Page 29 of the earnings release kit. We have added to our hedges for Millstone in 2013, but have left the 2012 position unchanged from last quarter. Our New England Coal units remain largely unhedged for 2012 and 2013, reflecting the low dark spreads currently available in the debt market. However, we were able to hedge about 10% of our expected output for 2012 due to a rise in power prices for the early months. The consolidated sensitivity in 2011 to a $5 change in New England power prices is now about $0.01 per share. Our sensitivity for 2012 is still only $0.05 per share. You should note that we are seeing an uplift in New England power prices as current market prices for 2013 are 3% higher than 2012. Also as Slide 8 indicates, market power prices for 2014 and 2015 are up 6% and 12%, respectively, over 2012. This validates our view that the drop in earnings for our merchant generation business will be in 2011 and 2012. Furthermore, we have begun to capture some of the uplift in 2014 and 2015 by layering in some hedges for Millstone in those years. We plan to begin disclosing these longer-dated hedge positions later this year. So let me summarize my financial review. Earnings for the second quarter of this year were very strong and at the high end of our guidance range. Operating results for each of our 3 business units either met or exceeded our guidance. We have hedges in place for a large portion of our remaining debt needs for this year and next. We have completed $600 million in share repurchases through the first half of the year, and we'll decide whether or not to pursue up to $100 million in additional repurchases later this year. Our operating earnings guidance range for 2011 remains at $3 to $3.30 per share. Third quarter operating earnings guidance is $0.90 to $1 per share. And finally, New England power prices in 2013, '14 and '15 show an encouraging trend that should help support our earnings growth targets going forward. We have begun to capture some of that growth with some longer-dated hedges. I will now turn the call over to Tom Farrell.

Good morning. We continue to move forward on our long-term infrastructure growth plan. Many of the projects announced at the outset of this program in 2007 are either currently in operation or nearing completion, and we are now well into the development of the next round of projects. These investments which we announced last September are spread across all of our regulated lines of business and provide the foundation for our growth in earnings and dividends. We see the potential for this growth to continue beyond the current 5-year window through the end of the decade. Since we began this program in 2007, we have added over 1,500 megawatts of generating capacity to our Virginia fleet, with the construction of a new combined cycle facility, peaking facilities, as well as upgrades to some of our existing plants. In May, the 580-megawatt Bear Garden Power Station in Buckingham County began commercial operation and has run for over 60 days without any forced outage or automatic trips. Bear Garden was completed on time and on budget. We will add another 585 megawatts next summer when the Virginia City Hybrid Energy Center, a coal and wood-burning plant in Wise County, is scheduled to begin commercial operation. Virginia City is about 90% complete and is also proceeding on budget and on time, with about 2,200 workers on site during this past quarter. Our next generating plant will be a gas-fired 3-on-1 combined cycle project in Warren County, Virginia that will provide approximately 1,300 megawatts when operational. The CPCN and Rider applications were filed with the State Corporation Commission on May 2, and an EPC contract was executed on June 30. EPC contract is fixed-price, which significantly reduces the risk of cost overruns to the company and its customers. Site work has commenced and the final notice to proceed was issued with the manufacturer of the major equipment. If regulatory approvals are received, construction should begin in the spring of next year and the plant should be in commercial operation in late 2014. The estimated cost of the project is $1.1 billion, excluding financing costs, or only about $821 per kW, which combined with its 6,600 heat rate, provides substantial economic value for our customers. Even with the planned addition of the Warren County plant, Virginia Power will still need to construct additional generating capacity to overcome its existing shortfall and to meet the demands of its growing service territory. We will provide periodic updates as we refine our growth plans. Virginia Power has also announced plans to convert 3 small generating plants from burning coal to less expensive waste wood as fuel. The air permit applications were filed at the end of May, and the CPCN and Rider applications were filed with the State Corporation Commission on June 27. An EPC contract, which is also fixed-price, was executed on June 30 and we are in the process of contracting with fuel aggregators for each of the facilities. The estimated cost of the conversions is $165 million and if the projects are approved by regulators, should be completed in 2013. On the environmental front, as you are aware, the Environmental Protection Agency issued its Cross State Air Pollution Rule earlier this month. In a change from the earlier drafts, the state of Massachusetts, where our Brayton Point Power Station is located, was excluded from the program. The program also excludes Rhode Island, where our Manchester Street Station is located. We are evaluating our compliance options for our generating fleet in Virginia, including installing control equipment, replacing some of our existing generation with new gas-fired facilities, adding additional transmission capacity, or some combination of all 3. We will discuss our full compliance strategy later this year when we file our integrated resource plan with regulators. The upgrade of our transmission system is a key component of our infrastructure growth plan. I'm pleased to announce that both of our major 500kv additions, the Meadow Brook-to-Loudon and the Carson-to-Suffolk lines are in service. Both were completed on/or ahead of schedule and within budget. Work has begun on the West Virginia portion of our next major transmission project, the modernization of the Mt. Storm-to-Doubs line. A hearing before the State Corporation Commission on the Virginia portion of the line was held on June 20, and we expect an order later this year. Work on this project will be conducted during the spring and fall of the next 3 years, and is estimated to cost about $350 million. Our electric transmission project pipeline contains over 40 additional projects, totaling about $500 million per year or at least each of the next 5 years. The growth program at our natural gas infrastructure business continues to move forward as well. You should expect to see a focus by us on a variety of midstream investment opportunities available in both the Marcellus and Utica Shale formations. Before turning to some developments there, let me update you on our midstream expansion projects that arise from the constraint conventional fields in the Appalachian basin. The Lightburn Extraction Plant, part of our Gathering Enhancement project, was completed during the quarter. The Charleroi propane truck loading terminal, which provides access to the Pittsburgh market, was placed in-service on June 3. Both projects were completed on time and within budget. Our $634 million Appalachian Gateway Project received approval from FERC last month. Construction will begin this summer, and the project should be in service by September 2012. Now to the shale opportunities. Last quarter, we announced 3 new projects which support Dominion Energy's 5-year growth outlook. These were the Tioga Area Expansion, the Allegheny Storage Project and our letter of intent between Chesapeake Energy and Dominion East Ohio to develop gathering systems to support Chesapeake's activities in the Utica Shale formation. Our next major project in the Marcellus and Utica regions has been finalized. We have acquired a site on the Ohio River in Natrium, West Virginia to construct a large gas processing and fractionation plant. With the rising price of oil and the depressed price of natural gas, drilling activity in the region has shifted from a dry gas to wet gas areas of the formation as producers look to capture the economic value of the natural gas liquids. As a result, the region has a significant need for additional processing and fractionation capacity. The Natrium site can access production in both the Marcellus and Utica Shale regions and is able to ship products via barge, rail, truck and pipe, offering significant value to producers. During the second quarter, we executed binding, gathering, processing and fractionation agreements with 3 customers. On July 1, we executed an EPC contract for the construction of facilities that can process 200 million cubic feet of natural gas per day and fractionate 36,000 barrels of NGLs per day. This phase of the project is currently over 90% contracted and is expected to be in-service by December 2012. Chesapeake Energy is the largest customer, having a commitment to provide 100 million cubic feet a day. The Phase 1 cost of Natrium for processing, fractionation, plant inlet and outlet natural gas transportation, gathering and various modes of NGL transportation is approximately $500 million. We can expand the facility to accommodate additional demand for producers and are currently working to secure additional commitments for a second phase of the project. Chesapeake Energy has an existing option for a portion of Phase 2. If the contracts are finalized, we would expand the facility to 400 million cubic feet of natural gas per day and 59,000 barrels of NGLs per day. The expansion of the facility would lead to a significant additional investment opportunity for our midstream business. With the continued successful development of the Marcellus and Utica Shale formations, interest in our Cove Point liquefaction project is growing as well. We are engaged in discussions with numerous potential customers in Europe and Asia, as well as producers in the Appalachian basin. At East Ohio, the company filed a request with the Public Utilities Commission to accelerate the previously approved 25-year, $2.7 billion barrel steel pipe replacement program to nearly double the spending to more than $200 million per year. We have reached a settlement agreement with the commission staff to increase spending by $40 million, bringing the total to $160 million per year. The proposed settlement is subject to the approval of the Public Utilities Commission. The hearing was held on July 22, and we expect an order in the near future. I'll now turn to operating results for the quarter, beginning with safety. Last quarter, I discussed the record safety performance from our Fossil & Hydro and Nuclear business units. This quarter, I want to highlight the safety performance at our natural gas businesses. Gas transmission's lost-time/restricted duty incident rate for the first half of the year matches its best ever performance. Dominion Hope recorded 0 OSHA reportable or lost-time incidents for the quarter and Dominion East Ohio recorded the best safety performance in over a decade. Cove Point was recognized for its safety and security performance, as well as its community involvement, with awards from the United States Coast Guard and the Southern Maryland Economic Development Association. Our other business units continue to register improving metrics for safety performance. Moving to operations, our generating plants performed well in the second quarter. Availability of our Fossil & Hydro fleet has been better than targets, particularly the utility large coal fleet, which achieved its best ever forced outage rate. North Anna Power Station and Millstone Unit 3 have operated at 100% capacity through the first half of the year. A spring refueling outage at Millstone Unit 2 was accomplished in a unit record 30 days. A spring refueling outage at Surry Unit 2 included a low-pressure/high-pressure turbine replacement, which was the final portion of the capacity upgrade project, expected to add about 40 megawatts. The tornado touched down on the site at the outset of the outage which combined with the valve malfunction, delayed the restart of the unit by about 25 days. Economic growth continues to drive improving results for Virginia Power. Projected demand growth in Dominion's service territory is the highest in PJM. Unemployment in Virginia is at 6%, well below the national average of over 9%, and is only 4.5% in Northern Virginia. New connects have been running below expectations, but sales growth has been strong. Weather adjusted, sales were up 3% in the second quarter after rising 2.1% in the first quarter. Last Friday, Virginia Power set a new all-time record peak demand of over 20,000 megawatts, an increase of nearly 2% over the previous peak set in August 2007. Several new data centers have been put into service or are nearing completion. Through the first half of the year, 5 new data centers have been connected, adding about 12 megawatts of new load to our system. We expect to add another 63 megawatts of new load from data centers by the end of this year. Our data center load, which was 295 megawatts at the beginning of the year, should grow to 545 megawatts by the end of next year and 715 megawatts by the end of 2013. Our regulatory calendar has been fairly active this year. I've already mentioned the recent filings related to our new growth projects at Warren County and the biomass conversions. Updates for the Riders for Bear Garden and Virginia City were filed on June 27. Last week, the State Corporation Commission issued an order in our annual commission rate Rider filing, approving an annual revenue requirement of $466.4 million, which fully supports recovery of the cost related to our growth projects. The new rate becomes effective September 1. On June 27, the State Corporation Commission approved our request to recover over $430 million in deferred fuel costs over a 24-month period rather than the traditional 12-month recovery called for in the statute. Our request for the extended recovery period reflects our desire to mitigate the impact on our customers. Finally, a few comments about our biennial review. As many of you know, the first biennial review under Virginia's reregulation statute takes place this year. We submitted our filing on March 31, and the SEC must issue an order by the end of November. Our filing demonstrates that our earnings governed by base rates for 2009 and '10 were within the 100 basis point approved range of 11.4% to 12.4%. Testimony from intervenors was filed last week and raised no unexpected issues. Staff testimony is due on August and hearings are scheduled for September 20. Virginia law allowed the SEC to revise the return on equity to be used in future regulatory proceedings although the governing criteria, such as the use of a peer group average of earned returns and the inclusion of premiums for operating performance and remitting renewable energy targets still apply. Our base rates cannot be changed as a result of this review. So to conclude, second quarter earnings were at the high end of our guidance range. We continue to improve our safety performance, which is already at the top tier in our industry. All 3 of our business units performed well and delivered results that met or exceeded our expectations. We continue to move forward with our growth plans, completing several major projects and beginning several more. This fall, we plan to provide more details around the next stage of our growth plan, including our plans for Virginia Power to comply with new EPA regulations, the continued build-out of midstream infrastructure in the Marcellus and Utica Shale regions, and disclosure of longer-dated hedging activities designed to lock in improving margins for our merchant generating fleet. Thank you, and we are now ready for your questions.

[Operator Instructions] Our first question comes from Daniel Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: I guess, Tom, first question, you said that you're going to readdress or kind of finalize the environmental CapEx plans due to the EPA rules due later this year. Can you just give us a little more clarity on timeline and kind of what the ROP process will look like?

Yes. And I'm referring to first with CSAPR, the so-called Casper rules have no material impact or significant impact on our environmental plans. So let's set that aside. When we've been talking about future capital expenditures, I think we announced maybe 6 months ago that we expected the Mercury rules, the now called -- or the HAPs rules to cost around $1.9 billion at Virginia Power. We don't see any reason to see that, that will change. We'll be within that range. We will give a lot more clarity around how exactly we will comply with HAPs when we file the integrated resource plan, which will be at the end of August. And we will explain where we plan to go on from there with the investor conference season starting in September. Dan Eggers - Crédit Suisse AG: Okay. And then on kind of the Cove Point conversation as far as export, any feel for when you guys might have something more substantial to talk about as far as maybe a plan or some memo use or anything like that?

Not at this time. When we're ready to announce something, we'll let you -- you will be among the first to know. Dan Eggers - Crédit Suisse AG: Okay. And then I guess just one other question. Clearly, there's been some interesting bidding activity on the market for other infrastructure opportunities similar to what you guys have in the Marcellus. This is an old question, I understand, but are you guys kind of, given the valuation discrepancy between what some of those assets trade at relative to where your stock is, have you guys been revisiting the idea of maybe pursuing other alternative vehicles to better represent the value of year Marcellus exposure?

I'll answer the, I guess, a macro answer to that question. I'll let Mark talk about the financing. To the extent the question asked, are we considering selling or spending our midstream business, the answer to that is no. And Mark can talk to you about financing options.

Yes, Dan, we see the Marcellus opportunities just continuing to grow based on our current location and our success with our early processing plants. And based on that and the spend requirement over the next several years, we're committed to our investment grade ratings. But we are looking at different types of financing options to finance this large level of growth as we go out there, all the ones that you might think about. And as we make progress on that, Dan, we'll let you know.

Our next question comes from Greg Gordon with ISI Group.

A couple of questions. Given how strong your earnings have been year-to-date, is it even necessary to contemplate doing the incremental $100 million in buybacks to get to the middle or the high end of your guidance range?

Greg, this is Mark. We talked about this previously. This is really an issue for 2012. As we looked at the buyback, we're entered into the buyback to make sure we're able to meet our 5% to 6% growth rate and keep our shareholders neutral to bonus depreciation. So we'll decide between now and the end of the year if we want to do the $100 million. It's not an '11 issue, it's potentially a '12 issue.

Got you. As we look at growth in demand in your service territory and how robust it is, are we -- should we expect more generation growth projects post the Warren plant coming online in 2014 to be presented to the commission as you see the demand continuing to grow out to the second half of that gate?

Yes.

And then what's the time -- the usual time horizon for presenting those resource plans to the commission?

Vague question, can't answer that question.

The integrated resource plan that Tom talked about earlier will be submitted no later than September 1, probably the end of August. And that will enumerate our plans to meet projected load growth in the state of Virginia.

And how far out will that plan go?

Typically, just 10 years.

Got it. And finally, when you talk about alternative financing plans, are you talking about using an MLP structure or is that off the table?

It's one of the structures we're looking at, but we're looking at others too, JVs, et cetera. But we're -- we are looking at an MLP structure.

Our next question comes from Paul Patterson with Glenrock Associates.

I'm sorry if I missed this, but the fractionation of the gas processing plant, what kind of contracting are you guys having with that? I mean, is it going to be a certain percent of proceeds or fee-based? Or can you give us a sort of a feel for what you might be seeing with that?

It's largely fee-based, almost entirely fee-based.

Okay. And then with respect to the Cove Point export potential, you guys obviously have a facility there, and that's obviously, I would think that there would be some synergy with that. But there is, my understanding, a considerable amount of CapEx with respect to an export facility as opposed to an import one. Any sense as to how much CapEx potential might be there?

Paul, it all depends on the size of the contracts that we sign. There is no prospect of us starting a liquefaction process without long-term contracts for an extended period of time that fully fund the expansion or the liquefaction itself. And it depends on -- we have to have a certain amount to make it worth our while to build at all or make it worth the while to customers to build at all. So we're a long way from deciding what the size it would be, although we are doing the studies now on how to size it and what it would look like and we're talking to vendors. And we're doing the market studies around impacts on gas price and all things you need to do to go ahead with this project. Interest has been strong.

Okay. Great. Then finally, I see that you guys are testifying this morning on the Minimum Offer Price Rule on the "self supply" issue. What we've also seen is that in other RTO environments, and I was thinking New England because you guys have Millstone there and what have you, efforts to reign in out of market subsidy impacts on the capacity market, in particular, I guess. Any sense as to whether or not there may be upsides that you might see from these activities with respect to the forward years and what have you in terms of the full capacity market? Any thoughts on that at all?

Yes, Paul, this is Mark. What we're focused on is protecting the interest of our customers in Virginia. The current rules define unconstrained zone versus constrained zone, the rules are different. As you know, some proposals were made to potentially change some of those rules down the road. And our total focus is to make sure our customers don't double pay essentially for capacity if the rules are changed in order to keep their rates down.

Sure. But I'm just wondering in New England, I guess, I know it's a different process and it's not as far along, but it does seem that there are efforts by others to basically sort of institute some sort of buyers side market mitigation efforts, I guess, right? Market power mitigation efforts. And again, I'm just wondering if you thought that, that might have some impact on the New England market or whether or not it's too early to tell or?

I think at this point in time, Paul, it's way too early to tell.

Our next question comes from Paul Ridzon with KeyBanc.

I know you can give an update later, but would you characterize your kind of post '13 hedging as dabbling? Or is it more substantial than that?

Look, we never dabble. That's a great question. I don't know how to define dabble, but we'll talk about that when we come out with the numbers in the fall. We'll let you decide but again, we want to make share everybody knows we're focused on uplifting these curves. We're focused on our 5% to 6% growth, and if that '14, '15 period we can lock in some value to support that, then we're going to move ahead and do that.

And just switching to another topic, can you discuss some of the potential synergies this processing plant will have with existing pipe? I mean is it going to increase the utilization and fees?

Yes. We'll be converting some of our existing pipes to wet to be able to provide liquids, et cetera. So the reason why this facility will be extremely competitive, and has been in the market, that's why it's sold out, is because we were able to integrate it with our existing gathering pipeline system. It's -- now the Utica Shale and the Marcellus Shale is bisected by Dominion Transmission's pipeline. And there are other pipelines, of course, in the same region. But this is our backyard and we've been there for 75 years and we have the infrastructure there to exploit the opportunities.

So what's the implication of Massachusetts not being part of Casper with regards to Brayton Point?

The implication is that we are -- we don't have to comply with the regulations. So whatever the limitations on admissions, et cetera, are inapplicable to Brayton Point and to Manchester Street.

So that makes them that much more competitive. Okay. Who's the EPC contractor on Warren County?

BMZ [ph], Burns MacZachary [ph].

And then finally -- the more -- every quarter, it seems like there's more projects in the pipe. I mean, at some point do we need to revisit the 5% to 6% growth?

Not at this time.

Our next question comes from Jonathan Arnold with Deutsche Bank.

Just curious on you're halfway through the year, you've had a couple of decent quarters. You nearly had a 10% range on the third quarter. Power prices are pretty well hedged for the rest of the year, but still a $0.30 range on the '11 guidance. Is that just a -- we'll revisit it when we get the third quarter down? Or what are the things that could really move you that much at this stage?

Jonathan, this is Mark. I think halfway through the year, as you know, we're a pretty weather-sensitive company in Virginia. We think to talk about any change in range at this early in the year will be premature. We'll see where we are at the end of the third quarter. But again, it's -- we're a third quarter company really on the electric side and we'd like to see what those results are before we talk about the range.

And if I may, on the NEPOOL fleet, it looked like you ran a good bit less than you anticipated in the second quarter, that you still managed to kind of deliver a number price-wise close to your hedge price. What was the reason for kind of -- there was it just dispatch? Was it operational issues? What pushed you off that generation target?

Jonathan, it's really market issues where we could replace our generation at a equal or lower cost with market purchases to settle our hedges. So those units didn't run as much, but we were able to make the same contribution as we would expect in running those units.

Our next question comes from Paul Fremont with Jefferies. Paul Fremont - Jefferies & Company, Inc.: When I look at the estimated annual NGL sales guidance, I guess it's on Page 29 of your packet, does the number for 2013 include the Natrium plant or is that not in there?

No. That's not in there, Paul. Paul Fremont - Jefferies & Company, Inc.: So this would essentially be a commodity-type sale, so can you give us a sense of what types of volumes -- I mean, it looks as if in '13, you could do close to 600 just on Natrium if you're at capacity.

We need to make sure we're clear on this. And I'm glad you asked the question, Paul. The Natrium processing fractionation facility is largely fee-based, okay? So we're not going to be selling, taking ownership of the NGLs, except a small fraction. So while that fraction is not included in what you see on the disclosures, as I understand it, it's not going to be -- it's not something that you should focus on, I don't believe, as to earnings power of Dominion. Paul Fremont - Jefferies & Company, Inc.: Right. But I guess, am I correct in sort of thinking about the fact that when Natrium is in operation, granted it's going to be at a much lower margin, that you're going to be looking at volumes that are sort of greater than the volumes that you're disclosing on that Page 29.

I'm not sure, to be honest with you, Paul. I'm just not sure I understand your question. Why don't you -- it would be better for you to follow up, I think, with our IR folks. We want to make sure we answer that really, and I'm afraid I just don't understand exactly what your point is.

And then I guess the other question I have is with respect to the cross state rules, and I recognize that any change in variable cost in VEPCO would probably be recoverable under a fuel clause. Can you give a sense of what you would expect to be the impact on your variable costs of operating those power plants?

In Virginia, we're in a good position with respect to the allowances that we expect to go into the bank. And we don't find ourselves in a short position and not predicting any material impact.

Our next question comes from Michael Lapides with Goldman Sachs.

Real quick, just looking at Page 13 on the slide deck, the various plants projects, all of those embedded in the CapEx guidance you gave for energy the last time you gave it, I think it was one of the analyst presentations over the last couple of months. So anything on that slide in the plants projects, those 4 items that is not embedded in that CapEx guidance that you gave a month or so ago?

We're checking the slide here, Michael, to make sure we answer your question. Natrium, we did not -- I mean, we didn't give you the amount in that slide. We have been talking about Natrium since the last quarter. We haven't finalized contracts until fairly recently. So while it shows up on Slide 13, the amount that we announced today is $500 million for Phase 1.

Okay. And the other 3?

The other 3 are in the plan.

Okay. The other 3 are in the plan. What's the timeline on the Utica Shale project?

He's talking about to you, Gary. Gary, why don't you answer that question?

Actually we'll be looking at that -- some of that gas will be ready to flow actually this year and more of it in 2012.

Okay. And I may have missed or I don't know if you discussed, did you talk about the scale in terms of the capital spending requirements for Dominion Energy for that, the Utica Shale Gathering Project?

You should actually consider that part to be relatively small. We're laying a few lines to help gather some of the new wells being drilled, but it's not a huge play for gathering.

Got it. And last question, this is on Virginia Power, and it's a little bit of a follow-up of one that someone asked earlier. When you look at your potential capacity needs between now and 2015, and do you see yourselves as needing incremental generation above what you already have in your construction plant to meet summer peak by 2015?

By 2015, I think the answer would be no. Because Warren will be coming in late 2014, but shortly after Warren, there is a need for increased generation in Virginia. As we look to the balance of the decade, there's still a significant shortfall that we're going to have to build with -- fill with new plant.

Our next question comes from Steve Fleishman with Bank of America.

Just on Natrium and, I guess on potentially other projects that come up like this, how should we think about the returns that you might be getting on a project like this? Is it -- I'm not sure you can be specific, but maybe generally, is this above utility returns? Or how should we think about returns?

Above utility return.

But still with long-term fee commitments in terms of revenue?

Yes, yes.

Okay. And I guess the second question on both the Casper rule and the HAP MACT rule, could you give any flavor either as your CEO position or in the EEI position, just current thinking how to react to those rules?

Well, I think first with HAPs, EEI will be filing its comments along with everybody else in about a week. I think it's August 6 is the date. We received a 30-day extension on the original 60 days. And I expect that EEI will be asking for some additional time for plants that will be retrofitted or replaced. I don't expect it to ask for additional time for plants that are being retired. Dominion has said we don't -- obviously the rule's not final, but from what we've seen, we don't anticipate any additional expenditures other than we projected originally, which was $1.9 billion at the high end of the possible range that we would have to spend. And that will be what we're trying to -- what we're finalizing is how we're going to -- what food groups we're going to use to meet those regulations, whether it's new power plants or environmental controls or transmission solution. We're nearly done with that, and that will become clear I think, in our IRP. The Casper rule, as I said, in particular because Massachusetts and Rhode Island were excluded from the regulation, there's no impact from the Casper rules on Dominion.

Our next question comes from Nathan Judge with Atlantic Equities.

I just wanted to see if you have any comments on the recent FERC ruling on transmission and as it relates to possible new transmission projects for you.

Paul Koonce can answer that question.

Yes, Nathan, we have been through the 620-page order. What they've done is deferred cost allocation to the RTOs, PJM's supports cost allocation at the 500kV level. So that's no change. And in terms of merchant transmission, again, I think the commission is deferring to the RTOs who developed those rules, but have given deference to where the transmission right-of-way currently exists or where facilities currently exist. We have a very constructive relationship with PJM, so we don't see really any impact from that as well.

Do you have any concerns or any issues with the ROFR decision?

Well, we did not have a ROFR in our FERC transmission tariff, but we do have a ROFR in our operating agreement with PJM. And again, the NOPR basically removes the ROFR from the transmission tariff does not impact us because we didn't have one, and has deferred the matter to the RTOs to develop the rules. So we've got a very constructive relationship with PJM. We're unaffected by the ROFR rule itself because we didn't have one, and I think we feel very good about our ability to carry on with PJM as we have in the past.

Great. And also could you just give us an update on perhaps timing regarding discussions of assets, perhaps disposals in your portfolio?

Well, the only asset that is up for consideration for disposal is Kewaunee as we have previously announced, and we have nothing to announce on Kewaunee today.

Is there a more definitive timeline that you're looking at now?

No.

Thank you. Ladies and gentlemen, we have reached the conclusion of our call. Mr. McGettrick, do you have any closing comments?

Yes, thank you. I appreciate everybody's attention today. And I just want to remind you that we'll be filing our 10-Q tomorrow. And our third quarter earnings release will be scheduled for October 28. Thank you very much.

Thank you. This does conclude this morning's teleconference. You may disconnect your lines and enjoy your day.